The invention relates generally to the field of geological formation evaluation and, more particularly, to a method for evaluating a geological formation which integrates well data and high resolution computed tomography of rock samples thereof. A system for performing the method also is provided.
Well log measurements can provide a number of rock properties needed to plan well completion and lateral placement. These properties include mineralogy, bulk density, porosity, electrical resistivity and elastic-wave velocities. Elastic-wave velocities and bulk density can be used to compute the elastic moduli needed to estimate the mechanical properties and strength of the formation. These mechanical properties are important for planning deviated and lateral wells and for fracture treatment. However, conventional well data resolution typically is only about 1.5 to 1.0 feet (about 46 cm to about 30 cm). This well data resolution typically is not high enough for evaluating some formations, such as thinly laminated formations which have thicknesses below the indicated level of resolution feasible with conventional well data.
Shale is an unconventional source of oil and/or gas. Shale rocks have not been studied extensively due to the fact that they traditionally were thought of as the source rock and not a potential reservoir because of their low porosity and permeability values. However, there are new methods to extract the oil and gas within these rocks, and therefore, there is great interest in analysis methods to characterize these rocks to better understand the mechanics of production from shales. Well data resolution alone typically is not high enough for evaluating thinly laminated formations of shale. The scale of lamination of shale can be measured in the cm or mm range significantly less than 1 foot (30 cm). Traditionally, there were only limited ways to analyze shale samples, and this began with scanning electron microscopes (SEM). The SEM image provides a two-dimensional (2D) picture or image of the sample that typically has a resolution of approximately 15-100 nanometers. Using only two-dimensional images, however, one is only able to estimate porosity and organic content. 3D CT imaging and/or FIB-SEM (focused ion beam combined with SEM) imaging have been proposed for evaluating some properties of shale, such as identification of the components, including the mineral phases, organic-filled pores, and free-gas inclusions; and computations of TOC (Total Organic Content), porosity, pore connectivity, and permeability in the three axis. Sisk et al, SPE 134582, “3D Visualization and Classification of Pore Structure and Pore Filling in Gas Shales”, 2010; Curtis et al, SPE 137693, “Structural Characterization of Gas Shales on the Micro- and nano-Scales”, 2010; Milner et al, SPE 138975, “Imaging Texture and Porosity in Mudstones and Shales: Comparison of Secondary and Ion-Milled Backscatter SEM methods”, 2010. However, this digital rock physics technology, e.g., 3D CT imaging and/or FIB-SEM technology, does not directly provide the elastic properties needed for computing the elastic moduli and other mechanical properties of the formation.
There remains a need for methods and systems to provide evaluations of geological formations that can combine well data with higher resolution digital rock physics in determining formation properties such as elastic properties or other mechanical properties thereof.